Hydrocarbon producing wells may contain many different formation liquids and gases such as methane, ethane, and other higher hydrocarbons, as well as carbon dioxide, hydrogen sulfide, water, and other compounds. In order to evaluate the commercial value of a hydrocarbon producing well, or as an aid in operations and well planning, it is often useful to obtain information by analyzing the component concentrations of the produced fluid from a formation or an individual well. Numerous systems have been developed to evaluate a downhole fluid composition and the relative component concentrations in the downhole fluid.
It has been found that certain components in downhole fluids can lead to corrosion. Among the problems encountered with well tubulars, corrosion may be the factor that causes the most losses. In general, there are four types of corrosion: sweet, sour, oxygen, and electrochemical. Sour corrosion is found in oil and gas wells that contain H2S (hydrogen sulfide) gas. H2S also presents health risks that need to be addressed and planned for. Wells may also produce other undesirable corrosive components such as CO2. A good understanding of the downhole fluid and gas concentrations is desirable in an attempt to control corrosion rates and to plan for safe development and production of the hydrocarbons.
Wellbore monitoring typically involves determining certain downhole parameters in producing wellbores at various locations in one or more producing wellbores in a field, typically over extended time periods. Spectroscopy is a known technique for analyzing downhole fluids, including drilling muds and crude oil. For instance, methods are known for analyzing drilling muds that involve reflectance or transmittance infrared (IR) spectroscopy. Spectroscopy is typically emitted in wellbore environments in the near infrared-range of from 1000 to 2500 nm. Spectroscopy is typically emitted in this range because near IR emitters and sensors are known to be easier to operate at well temperatures while longer wavelength emitters have shown limited output optical power under similar well conditions.
Typically, spectroscopy monitoring involves obtaining a formation fluid sample downhole and bringing the sample to the surface where measurements and processing of the resultant data takes place. These measurement methods are typically utilized at relatively large time intervals and thus do not provide continuous information about wellbore condition or that of the surrounding formations.
Methods for analyzing downhole fluids can include the use of wireline tools. Methods of measuring using wireline tools include lowering a wireline tool including an analyzer into a wellbore at a desired depth. These wireline tools may contain spectroscopic imaging tools for detecting the contents of downhole fluids. An alternate method can include the use of tubing for conveying the tools downhole. The tubing can be conventional jointed tubing or could be coiled tubing or any other suitable types of tubular pipe. The tubing can be wired, such as having signal conveyance wires connected or adjacent to the tubing for providing a means of transmitting signals to the surface.
Other methods for analyzing downhole fluids can include the method of logging while drilling (LWD) or measurement while drilling (MWD). LWD and MWD are techniques of conveying well logging tools or measurement tools into the wellbore as part of a bottomhole assembly. During drilling of the wellbore, these downhole tools are disposed in a bottomhole assembly above the drill bit. In some methods, LWD/MWD tools contain spectroscopic imaging tools for detecting the contents of downhole fluids.
In a current H2S detection method, H2S is detected by spectroscopy using an indirect method wherein metal ions are mixed with H2S, thereby forming metal sulfide. The metal sulfide is then subjected to near-range spectroscopy to detect the amount of metal sulfide present downhole. The amount of metal sulfide detected by spectroscopy can be used to indicate the amount of hydrogen sulfide present downhole. The metal sulfide produced from this method, however, may contaminate the oil in the wellbore.
In a current CO2 detection method, a sample is decompressed to enable gaseous components to come out of solution from the sample. The gaseous components are then analyzed and CO2 is detected by spectroscopy. The content of the CO2 in the sample is then determined by the results of the liquid and gaseous analysis. Therefore the CO2 in the sample is determined indirectly.
Therefore, there is a need to directly detect H2S and/or CO2 in a downhole environment without causing further contamination and without the separation of gaseous components from the sample being analyzed. In particular, it can be desirable to detect H2S and/or CO2 in a wellbore without stopping production. In addition, it can be desirable to obtain a continuous reading of H2S and/or CO2 in a wellbore during production. Thus, a need exists for a method of directly detecting both H2S and CO2 downhole.